Despite the now-routine use of prestack depth migration (PSDM) for unconventionals, confusion abounds on the topic of how to best incorporate near-surface velocity estimates into the PSDM shallow-model-building process. The present work seeks to eliminate the confusion via a carefully-controlled synthetic experiment in which the (known) near-surface velocity distribution mimics typical Permian Basin shallow geology. In this experiment, various methods for near-surface model building are tested, ranging from simplistic to sophisticated, and PSDM results are compared against the ideal image. These tests clearly demonstrate that gather flattening improves dramatically with application of the more sophisticated shallow model building approaches. In the case of the most primitive approaches (e.g, migration-from-flat-datum or migration from topography where the shallow velocity cells are flooded with a spatially uniform “replacement” velocity), the migrated gathers exhibit significant residual moveout, and applying a tomographic velocity update to improve flattening leads to a significant error in event depth location (i.e, “depthing”). This depthing error suggests that downstream anisotropic parameter estimation will be compromised unless a more sophisticated shallow model building approach is employed. The concept of differential statics is introduced and is demonstrated to be a useful tool which can provide good gather flattening, accurate event depthing, and also improved lateral continuity of events in the common case where the near-surface velocity estimate from refraction statics analysis is not suitable for verbatim insertion into the shallow PSDM model. Key findings from the synthetic experiments are corroborated by analogous observations on real data, suggesting that the experiments are indeed capturing realistic effects.
It is well known that near-surface heterogeneity can cause significant traveltime distortion of reflected signals, and, furthermore, that such distortion poses a major challenge in land seismic imaging. Addressing this challenge is particularly important in unconventional plays, where accurate depthing of subtle features is crucial for applications such as landing and steering optimization. Recently, some notable advances have been made, including the use of novel refraction statics techniques (Diggins et al., 2016), application of full-waveform inversion (e.g., Roy et al., 2017), and incorporation of gravity/EM data (Colombo et al., 2012), all of which seek to better estimate the near-surface velocity field. At the same time as these advances are unfolding, prestack depth migration is beginning to see widespread use in many North American unconventional shale plays (Rauch-Davies et al., 2018).
Publicly-available fault data for the Delaware basin is used to simulate a detailed map of maximum stress direction at a scale of 1000ft x 1000ft throughout the Delaware basin. The resulting maps highlight the complexity of stress fields in the Delaware basin and the importance of accounting for the interaction of entire fault systems with regional stresses. This underscores a dire need for the industry to better quantify structural features in and around unconventional reservoirs. When commercially-available seismic data is used for a refined interpretation of the structural features that affect the stress field, geomechanical models can be refined to provide valuable information at the well and pad scale to influence and optimize well spacing and completion decisions to minimize frac hits and other undesirable well interferences. Multiple data collected at the wells are used to validate the predicted stress orientation and their impact on the performance of hydraulic fracturing jobs. These results were enabled by the use of validated geomechanical modeling that is able to easily handle the faults and natural fractures. This is implemented by using the material point method to address the computational challenges introduced by the presence of these earth discontinuities in the general continuum mechanics equations representing the static and dynamic variations of stress in unconventional reservoirs.
Production of unconventional wells is dictated by both the geological (resource) and geomechanical (recoverability) properties of the reservoir. The geomechanics of a reservoir can be broken down into the rock mechanical properties, which near the wellbore primarily control fracture initiation potential, and the current stress state, which away from the wellbore controls the propagation of successfully induced hydraulic fractures and their interaction with natural fractures and layer interfaces. The consequential properties of the stress state can be further refined and represented as the differential stresses and the maximum horizontal stress orientation. In the Permian basin where a normal fault regime is common, it is critical that an unconventional horizontal well be drilled nearly perpendicular to the maximum horizontal stress direction (MHSD) in order to induce transverse hydraulic fractures and thereby maximize its stimulated reservoir volume (SRV). Additionally, maximum horizontal stress orientation is a major control on fault stability and a primary concern when quantifying the induced seismicity potential in a given area. Stress rotations have been documented at regional, basin, field, and pad scales (Umholtz & Ouenes, 2015, Umholtz & Ouenes, 2016, Ouenes et al., 2016). What cannot be ignored, is the reciprocal relationship between fault networks and stress fields. While fault quantification is readily available at field scales (when seismic data exists), operators rarely disclose these interpretations to be used in comprehensive regional studies. This study will initially focus on quantifying stress rotations at basin and county scales using publicly-available data, and further refine these estimates by integrating interpreted fault information from readily-available seismic data.
Total organic carbon (TOC) as measured by laboratory techniques from core historically has been used to assess the quality of source rocks. Now, TOC measurements are widely used to help evaluate unconventional reservoirs/resource plays and to more optimally target and design lateral wells to achieve maximum productivity. This paper describes a method to estimate TOC from wireline logs and visualize its distribution across the entire Delaware Basin.
Hydrocarbon exploitation in the Delaware Basin is currently focused on the Wolfcamp and Bone Spring Formations, however proven productive zones occur in the stratigraphic section from the overlying Delaware Mountain Group to the Ordovician Ellenburger. Known regional source rocks throughout the section include the Ordovician Simpson, Devonian Woodford, Mississippian Barnett, and potential local sources in the Pennsylvanian, Permian Wolfcamp and the Avalon shale member of the Bone Spring. To gain insight into the basin's petroleum systems, we describe a convenient approach to comparatively view source richness and distribution estimates from a basin-wide perspective.
Traditional sample based methodology uses TOC datasets from laboratory measurements that are displayed by plotting and contouring TOC values on a 2D map. This may be appropriate for thin homogenous shale formations, but for thicker heterogeneous source beds maps offer little flexibility in viewing and analyzing the data. More recently, petrophysical methods to derive TOC from wireline logs have been proposed and tested in several basins globally (eg Passey et al., 1990 & 2010, Issler et al., 2002). Those methods were not easily applicable here, the Passey method because of abundant calcite in the sediments and the need for good thermal maturity control, and the Issler method because of the general paucity of good quality sonic log coverage in the Delaware Basin.
Our project derived a petrophysical model to estimate TOC through the Bone Spring and Wolfcamp by calibrating ~1900 core measured TOC values from 57 wells to wireline curves. A calculated TOC curve was generated for each lithostratigraphic unit as appropriate using RHOB as the primary input (continuous DT curves were sparse in the wells with sample data). GR and borehole rugosity cutoffs were applied to constrain the calculation. The model was then applied to 872 wells across the basin and interpolated to provide a 3D volume of estimated TOC. The calculated curves and 3D model were QC'd visually and semi-statistically and found to be a reasonable match to the core data, given the methodology
The Mississippian section, in particular the Meramec and the Devonian Woodford continue to be the preferred investment targets in the SCOOP/STACK trend in Oklahoma We showcase here the seismic characterization of these formations using multicomponent seismic data in the STACK area and the conventional vertical component seismic data in the SCOOP area, using deterministic prestack impedance inversion. The joint impedance inversion carried out over seismic data from the STACK area was used to derive rock-physics parameters (Young's modulus and Poisson's ratio), which showed the sweet spots that are distinct spatially, rather than bleeding off at the edges. The added advantage of joint inversion was that the density attribute could also be derived therefrom, which was not possible for the data from the STACK area. In addition to density, the results from prestack joint impedance inversion have been found to be superior to the simultaneous inversion. The equivalent attributes (besides density) derived for the SCOOP area also show promise.
The Oklahoma SCOOP play extends about 200 miles along the east flank of the Anadarko Basin, and along with the STACK play, have become one of the most active unconventional plays in the US. The trend has gathered attention due to its potential for oil and liquids-rich gas yields, record-setting IP from wells, superior economics and proximity to pipelines and infrastructure. Consequently, oil companies are making huge investments in these plays.
SCOOP is an acronym for
The Delaware and Midland Basins are multistacked plays with production being drawn from different zones. Of the various prospective zones in the Delaware Basin, the Bone Spring and Wolfcamp formations are the most productive and thus are the most-drilled zones. A 3D seismic survey was acquired in the northern part of Delaware Basin and after processing was picked up, to understand the reservoirs of interest and pick the sweet spots. The whole reservoir characterization exercise was carried out on this data in three different phases. We discuss phase 1 here, beginning with a brief description of the geology of the area and the stratigraphic column, and going on to the well ties for the different available wells over the 3D seismic survey, estimation of the shear curves where the measured shear curves were missing, the generation of an accurate low-frequency model for impedance inversion, preconditioning of the prestack seismic data, use of different lithotrends in inversion and finally the prestack simultaneous impedance inversion.
The Permian Basin in west Texas and southeast New Mexico is the most prolific of all the basins in the US. The Delaware Basin forms the western subbasin of the Permian, the Midland Basin the eastern part, and both are separated by the Central Basin Platform (Figure 1). The Delaware and Midland Basins are multistacked plays with production being drawn from different zones. Of the various prospective zones in the Delaware Basin, the Bone Spring and Wolfcamp formations are the most prolific and thus the most-drilled zones.
3D seismic data acquisition and processing
A three-dimensional seismic survey was acquired in the Delaware Basin, spread over the Ward, Loving and Winkler counties (Figure 1). The size of the seismic survey was 407 mi2 (1050 km2) and its acquisition completed in November 2017. The seismic data had 2 ms sample interval, 5 s record length, and with a bin size of 82.5 ft. by 82.5 ft. (25.2 x 25.2 m). The processing of this large data volume was completed in May 2018 with anisotropic prestack time migration (PSTM) gathers and stacked volume with 5D interpolation.
The processing of the data was completed in April 2018 and picked up with the objective of seismic reservoir characterization that would help in understanding the reservoirs of interest and prove useful towards cost-effective drilling.
This talk explores the recent production history in the Powder River Basin, providing a comparison of wells drilled between 2011 to 2016 vs. wells drilled in 2017 and 2018. We highlight an improvement in well performance that warrants a deep-dive examination correlating to landing zone, lateral length, proppant and fluid factors, and other completion variables. Data is mined using the TGS Well Performance Database that contains historical monthly oil, gas and water production volumes at the well formation level. This detailed dataset, correlated to producing formations, helps feed our data driven model to study individual formations and their potential productive capabilities. Estimated Ultimate Recovery (EUR) wells are forecasted to their economic limit and forward curves are generated utilizing hyperbolic fitting backed up with the Extended Kalman Filter procedure. Completion data is used to statistically evaluate relationships between production and operations.
Following analysis of well performance metrics nine formations stand-out with attractive production rates and EURs. The top formation targets include the Turner, Frontier, Parkman formations, and the Mowry Shale. Our research shows how correlations in production metrics to landing zone, lateral length, proppant & fluid factors, and other completion variables have contributed to a dramatic improvement in well economics in the recent two years. Analyzing horizontal well performance over time; 2018 horizontal well EURs have increased an impressive 270% over 2011 horizontal wells.
The Powder River Basin (PRB), located in northeastern Wyoming and southeastern Montana, USA has produced conventional oil and gas since the 1890's, highlighted by the 1908 discovery of the Shannon and Salt Creek fields north of Casper, Wyoming (Anna, 2009). Recent advances in horizontal drilling and multi-stage hydraulic fracturing renewed interest in the basin to test the economic viability of tight sandstone and carbonate resource plays (Toner, 2019). Since 2009, oil production in the Powder River Basin has increased 200% due to horizontal drilling that is mainly targeting the Turner/Wall Creek, Parkman, Niobrara, Sussex, and Shannon formations.
The PRB is known as an oil basin however, in the late 1990's Coal Bed Methane (CBM) development greatly increased gas production. In 2009, the PRB produced 584 BCF of natural gas. Natural gas production has been declining in the PRB since 2009, largely due to low gas prices, depleted CBM reservoirs, and competition from unconventional gas plays.
Least-squares reverse time migration (LSRTM) mitigates the illumination problems caused by complex geologic structures, nonuniform acquisition geometry and limited recording apertures. It is theoretically accurate in producing image gathers more suitable for amplitude versus offset (AVO) analysis. We applied image-domain LSRTM in the gather domain with nonstationary matching filters to generate LSRTM gathers with amplitude better preserved. First, we use an acoustic synthetic example to illustrate the idea and verify the results. Then it is applied to a wideazimuth (WAZ) survey in Gulf of Mexico.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 207A (Anaheim Convention Center)
Presentation Type: Oral
Full waveform inversion (FWI) in recent years is widely used in the Gulf of Mexico area to optimize the accuracy and resolution of the subsurface velocity model. A velocity model using tomography is heavily dependent on the signal-to-noise ratio of the migrated common image gathers (CIG). Events are well defined on the CIG under the gas pockets, which makes it difficult to derive decent quality residual moveout picks (RMO) for input to the tomography engine. Adapting a model-building approach from the image domain to the data domain in such a geological scenario can help improve the velocity model and therefore the final image quality. The presence of a salt reflection in the Gulf of Mexico (GOM) data causes a big mismatch between the observed and predicted data near the top of salt boundary due to an inaccurate salt model. Eliminating the reflection associated with the salt from the observed data can help reduce the effect of a mismatch near the salt boundary from the data residuals when starting with a sediment-only model. We present this full waveform inversion (FWI) case study in an area of the GOM where our workflow helped capture the gas anomaly in the model and to improve the sediment model by damping the effect of salt-related energy from the input to the FWI.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: Poster Station 7
Presentation Type: Poster
This case study presents results from 3D Gambia Blocks A1 and A4 Kirchhoff prestack depth migration (KPSDM) project offshore Gambia. The main purpose of this project is to produce a more accurate velocity model which would enhance event placement and improve the sediment events below Aptian unconformity. TTI anisotropic prestack depth migration and tomographic velocity updates including image guided (IG) and horizon constraint tomography are used. Because of the complex geology above the unconformity, the stratigraphic horizons were interpreted for the high-resolution tomography.
Presentation Date: Tuesday, October 16, 2018
Start Time: 9:20:00 AM
Location: Poster Station 21
Presentation Type: Poster
The TGS Gigante project is comprised of 188,497 km of 2D seismic data acquired in 2016 and primarily covering the offshore Mexican side of the Gulf of Mexico (Figure 1). Within the survey, 180 seismic lines with 5 km average spacing are in the increasingly important Yucatan area, where active hydrocarbon exploration is taking place. The data was acquired with a 12 km streamer length and a 2 ms sample interval. Both Kirchhoff and Reverse Time Migration significantly improve the seismic image quality in the structurally complex offshore Yucatan area.
The Yucatan in offshore Mexico is a relatively underexplored area, where a better understanding of the regional geology is still in progress. Due to lack of well control, a clear conceptual geologic model is required before starting seismic interpretation work. Detailed salt interpretation improves image quality in presalt sediments, resulting in a better definition of potential plays. In this case study, we present salt interpretations, based on regional tectonic knowledge, towards the improvement of image quality. With high resolution imaging and seismically constrained interpretation, the deeper Mesozoic section stands out for the presalt plays in Yucatan, offshore Mexico.
Understanding the structural orientation of the basin, and salt flow directions with reference to 2D line acquisition geometry, is a necessity for seismic interpretation. The existing 2D lines follow the strike and dip orientation of the basin. Large salt diapirs with wide pedestals and shallow steep overhangs are the most common structures in the area. However, small rollover autochthonous salts and reactive diapirs, attached to the extensional growth fault systems, are also identified in the Yucatan salt basin.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 210C (Anaheim Convention Center)
Presentation Type: Oral